NIGERIA - The Shell-Led Group.
Shell Petroleum Development Co. (SPDC) holds 30% in the JV. Shell D'Arcy was the first major to pioneer Nigeria from 1936 and to put this country on the map of oil producers in 1958. Shell, the operator of the JV, plays many other roles. Most important among these roles are the following:
Its CEO Ronald van den Berg acts as a spokesman for the other foreign oil firms operating in Nigeria during crises with the government. He has been warning Obasanjo's government since late May 1999 that failure to meet cash-calls by NNPC would result in a drastic reduction of work and staff, with the JV's capacity to fall as a result.
On Feb. 8, 1999, Van den Berg announced an $8.5 bn Shell plan to raise output capacity by 600,000 b/d and increase gas production and exports considerably within five years. A major part of new production is to come from deep offshore fields under separate PSCs, led by Bonga and EA which are giant oil and gas structures.
In January 2002, Shell and its JV partners announced a three-year plan to invest $7.5 bn in this country's petroleum industry. A big part of this is going new phases of the Shell-led Nigeria Liquefied Natural Gas (NLNG) project, the biggest energy investment in Sub-Saharan Africa (see Part 3), and Shell's is to raise its Nigerian oil production capacity to 1.6m b/d by 2010. Shell's share of the new investment was $2.4 bn.
The 1999 and 2002 plans will enable Shell to eliminate gas flaring by 2008. All its flow stations and processing units will have equipment to harness associated gas, which will be supplied to the domestic market.
On behalf of the group, Shell supplies almost 90% of all gas to industry and the power sector in Nigeria. A Shell priority is a set of projects to collect and utilise associated gas and end flaring in its areas by 2008.
Shell has an expensive multi-faceted plan to resolve numerous communal problems in the oil-rich areas, including projects to improve the environment in the Niger Delta. It has faced complex problems and violence in Nigeria since it came to this country.
NNPC holds 55% in the JV. This was reduced from 60% when the cash-starved NNPC was compelled to cede 5% to Elf (which now is part of Total). In return, the French firm increased its share in funding the group's expensive development plan.
Total holds 10% in the JV. Total (Elf) leads another producing JV in Nigeria (see Gas Market Trends) and its local unit has good knowledge of the country's geology, Elf having found major oil reserves off Angola. Total is also a partner in the LNG venture. Agip holds 5% in the JV and is a partner in the LNG venture. It leads a JV with NNPC producing a light/sweet blend of crudes from a number of fields. Agip also produces 10,000 b/d of oil elsewhere in Nigeria under a PSC.
Shell's production system consists of two regional divisions, with each led by a high-powered executive: the Eastern Division has the capacity to produce more than 600,000 b/d of the Bonny group of crude oils; and the Western Division which can produce another 500,000 b/d of the Forcados group. Nearly all the fields in the two groups are onshore, with some extending to the shallow-water offshore in the Niger Delta.
The Eastern Division has seven groups of fields yielding light/sweet crude oils blended into Bonny Light and heavier ones blended into Bonny Medium. They include Nembe and its satellites (250,000 b/d cap); Cawthorn Channel and satellites (100,000 b/d); Ekulama and satellites (100,000 b/d); Imo River (25,000 b/d); Kolo Creek (25,000 b/d); Adibawa (20,000 b/d); and Etelebou (20,000 b/d). Bonny Light and Medium are exported from the Bonny island terminal.
The Western Division has six groups producing crude oils for the Forcados blend exported from Forcados terminal, including Estuary South Bank and satellites (100,000 b/d); Jones Creek (30,000 b/d); Otumara (20,000 b/d); Olomoro (20,000 b/d); Sapele (20,000 b/d); and Egwa (15,000 b/d).
Bonny Light, 37.6*API with 0.13% sulphur, is a gasoline-rich blend also known as Nigerian Light. Bonny Medium (Nigerian Medium) is rich in gasoil and gasoline: 25.7*API with 0.24% sulphur. Forcados, 30.5*API with 0.2% sulphur, is particularly rich in gasoil. The three blends are popular among European, US and Asian oil refiners.
A big number of discoveries made by Shell since 1985, after it introduced the 3-D seismic system in Nigeria, were developed quickly to replace depleting small fields discovered in the late 1950s and early 1960s. Some of the large oilfields have since kept producing. A number produced at higher rates because Shell discovered additional formations beneath them.
New fields in the Forcados group are Tunu which went on stream at end-1995 to produce 10,000 b/d, and Kanbo and Ogbotobo which went on stream in 1998 with a combined capacity of 80,000 b/d.
Discoveries made since 1990 have added over 1.2 bn barrels to the JV's proven oil reserves and there have been several gas finds. They include Gbaran-4, found in 1990, which was the biggest discovery in Nigeria for ten years, with 400m barrels of oil and 500 BCF of gas. Since it introduced the 3-D system, Shell has been revising estimates for existing oil and gas reserves. A re-evaluation of seismic data and well results from major oil fields is a constant process, as in the case of other major operators. Shell has recently tendered contracts for 3D and 4D seismic acquisition work in the Niger Delta, to be done from early 2004 to late 2006 in both its eastern and western divisions.
Shell has revamped both the Bonny and Forcados terminals. It has modernised its network of pipelines.
Shell in December 2002 started limited offshore oil and gas production from the EA field in the Gulf of Guinea off southern Nigeria. Shell later said production had begun a week ahead of schedule, at its new floating production storage and offloading (FPSO) vessel. The first cargo was loaded in early January 2003. Now the field is producing about 75,000 b/d.
The FPSO vessel, 'The Sea Eagle', is the third largest in the world. During the violence in April 2003, Shell took the unusual step of advertising in Nigerian newspapers to highlight threats to attack this vessel by "criminal elements", whom it said were planning to set fire to 'The Sea Eagle'.
The natural gas from EA will be transported through a offshore gas-gathering system which is now under construction. It will be converted to LNG at the Shell-operated LNG plant on Bonny Island.
The EA field, on Block OML 79, is located in shallow water and was first discovered in 1965. With estimated reserves of 350m barrels of oil, the EA field is expected to peak at 140,000 b/d of oil and 100 MCF/d of gas. EA crude is light - 38*API - with less than 0.1% sulphur contents. The partners in the EA field are Shell (30%), NNPC (60%), and Total (10%).
Work is continuing on development of Shell's massive Bonga deep-water field on Block OPL 212, which has the potential to produce 225,000 b/d of oil and 150 MCF/d of gas. Bonga is estimated to contain 700m barrels of oil and it is scheduled to come on stream in the first quarter of 2004.
Shell is the operator (55%), partnered with ExxonMobil (20%), Agip (12.5%), and Total (12.5%). The field will be serviced by a 2m-barrel FPSO vessel.
The 300,000-ton hull of the Bonga FPSO vessel, built by Samsung in South Korea, arrived at Amec's yard in Wallsend on the River Tyne in Newcastle in November 2002. The hull is 300 metres long, 75 metres wide (including the helideck), and has the height of a 12-storey building. Topside modules, being fabricated in north-east England, the Netherlands and Nigeria, will be installed on the Bonga hull at Wallsend. The FPSO vessel will be towed to its permanent mooring at the Bonga field, 120 km of the coast of the Niger Delta. It will be located in 1,000 to 1,100 metres of water.
In May 2001, Shell announced a second major discovery on Block OPL 212 (OML 118), which contains the Bonga field. Bonga South West is estimated to contain recoverable reserves of nearly 1 bn barrels of oil. Drilling on the Bonga South West development will be completed in 2003 with the first oil produced, also by a FPSO vessel, expected in 2005. Shell has indicated that by then oil output from the two Bonga fields will total 350,000 b/d.
Part of Bonga South West extends to ChevronTexaco's Aparo oil prospect on the OPL 213 block, where the US major in August 2002 completed drilling of the Aparo-2 appraisal well to a depth of 3,527 metres beneath 1,245 metres of water, 5.5 km north of the Aparo-1 discovery well which was drilled in 2001. ChevronTexaco said it had encountered a "substantial" amount of net oil sand and the well had been suspended following a "successful drill stem test", confirming the commercial viability of OPL 213.
The managing director of ChevronTexaco's mid-Africa strategic business unit, Jay Pryor, was in August 2002 quoted as saying: "We will be working jointly with the OML 118 operator (Shell) over the next few months to ascertain the optimum development of these resources" - thus suggesting a joint development of both blocks. But a Shell spokesman was quoted as responding that, while a "part of the (Bonga South West) accumulation may extend into OPL 213", it would be "premature to comment on whether this had any implications for development". So far, negotiations between the two majors have been inconclusive.
Shell's other main production sharing contract (PSC) prospects under deep water are the Bolia oilfield in OPL 219 and the Doro gas field, also in OPL. Shell's partners in these are ExxonMobil, Agip and Total.
The Bolia-1X discovery well, drilled under 1,100 metres of water 110 km offshore, in January 2002 flowed at a test rate of 6,000 b/d. Doro, under 1,000-1,200 metres of water some 120 km offshore, was found in 1999. Later it was discovered that Doro extended to Statoil's OPL 218, where the Norwegian company had found the Nnwa gas field in 1999. The two will be developed jointly by Shell and Statoil for a floating LNG/GTL export plant (see Part 3 in Gas Market Trends No. 7 next week).
In January 2003 Statoil confirmed a gas discovery in its OPL 218 block, following completion of the Nnwa-2 appraisal well. The results of Nnwa-2 indicate continuity of the main gas reservoir intervals across a large structure extending into the adjacent Doro field. Statoil and Shell signed an MoU with NNPC and the federal government in June 2002 to conduct a feasibility study for a joint development of Nnwa/Doro system, said to contain 9.5 TCF of recoverable gas, and the proposed floating LNG) facility. Statoil's partner in OPL 218 is ChevronTexaco's affiliate, Texaco Nigeria Outer Shelf Ltd.
In January 2002 a $540m contract was awarded to Shell by the National Electric Power Authority (NEPA) for two major gas-fired projects at the Afam Power plant near Port Harcourt. Under the contracts - to refurbish, operate and transfer (ROT) the Afam I-IV plant and to lease, operate and transfer (LOT) the Afam V plant - Shell in 2002 took over the assets and began operating the Afam power plant for a period of 15 years.
The projects were undertaken in conjunction with Eskom Enterprises of South Africa. Eskom is handling the daily running of the plant and supervising the overall contract and project management of the construction phase.
Shell Nigeria Gas is marketing natural gas in the country. In January 2003 Shell and its partner, Nigerian Gas Co. (NGC), connected 30 industrial firms in the Agbara/Ota areas of Ogun state to their $34m gas transmission and distribution project.
In the first quarter of 2003, Shell supplied 938 MCF/d of natural gas to the Nigeria Liquefied Natural Gas (NLNG) company, 60% of the feedstock required by the LNG facility. Shell had raised its gas output to NLNG due to its need to meet its contractual obligations to supply the facility's third train.
Senior Shell executive Nick van Ooyen in November 2002 told a conference of the Nigerian Association of Petroleum Explorationists that the Niver Delta still had the potential of 40 bn barrels of reserves yet to be found, adding: "We also believe that much of this potential will be found in new play types". Shell (SPDC) in 2001 launched a seismic and shallow-water drilling to effect "a reality check" on the area. Four wells were drilled in 2001 and two in 2002. He said: "The future for SPDC lies in testing new pay opportunities and so we need to build up our database. In spite of our 93% success rate over the past two years, during which we have added 766m barrels to recoverable (oil) reserves with only 15 exploration wells, about a third of our discoveries were surprises and so our ability to predict pay columns remains a major challenge".
Ooyen also said: "Right now we have 27,000 sq km of 3D seismic covering 80% of our Nigerian acreage and we aim to have full coverage by 2006". The recoverable oil reserve base of the Shell-led consortium in the Delta is in excess of 10 bn barrels. He said in 2002 Shell had logged several 100m and 200m barrel deposits "very close to existing fields in conventional sequences throughout the Delta".
In late April 2003 a Shell spokesman said Nigeria was losing an average of 200,000 b/d of crude oil, or some 10% of its total output, due to theft. The revelation came as the Department of Petroleum Resources (DPR), regulator of Nigeria's oil and gas operations, said the country's proven oil reserves had risen to 34 bn barrels by end-March 2003. Shell officials say their firm alone lost an average of 100,000 b/d in 2002 to theft.
Shell has reduced gas flaring in its operation by about 33%. Shell's external relations director Precious Omuku disclosed this during the media presentation of the company's 2002 People and Environment annual report in Lagos on April 30. He said the reduction was a part of Shell's efforts to meet the 2008 gas flaring deadline.
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|Publication:||APS Review Oil Market Trends|
|Date:||Aug 11, 2003|
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